Directional wellplans represent a 'perfect' wellpath; curves have a perfectly constant dogleg severity (build and walk) and tangent sections are perfectly straight (i.e. DLS = 0.00). This is of course completely unrealistic (a curve will always be drilled with a varying DLS and tangent sections are never perfectly straight), so it will result in underestimating torque and drag values.
Softdrill NL Torque & Drag provides the option to apply 'random' tortuosity to the wellpath.
Random tortuosity should never be applied to actual survey data. However, in case a wellplan is tied on to actual survey data (e.g. a sidetrack wellplan), tortuosity may be defined for the planned part of the wellplan.
Currently three random tortuosity options are available. Each is defined with the top and bottom measured depth (MD From and MD To) of the section to which it should be applied, as well as a period and magnitude:
Random Inclination & Direction
The random inclination & direction method is similar to the random inclination, dependent direction method described below with the exception that the variation in the hole direction is independent of the inclination.
This method is suggested for vertical sections with a rotary assembly (e.g. drilling to kick off point).
Random Inclination, Dependent Direction
This method applies a random variation, within the magnitude specified, to the inclination and hole direction. The variation in hole direction is inversely proportional to the inclination (i.e. the higher the inclination, the lower the variation in hole direction). This method is suggested to simulate sections where a steerable motor is used (e.g. build up sections).
A typical value for the period is 30m or 100ft to simulate variations per stand drilled.
The magnitude is typically used to simulate steerable motor runs to reflect the expected deviation from the desired steering result. For example, if during a build section, the inclination and direction are expected to deviate within 0.50° from the planned/desired values, a magnitude of 0.50 should be entered. As a result, the actual variation at individual (simulated) survey stations will thus be between 0.00 and 0.50.
The sine wave method modifies the inclination and hole direction of the individual (simulated) survey stations to simulate a sine wave ripple along the well trajectory.
A typical value for the period is 300m or 1000ft to simulate variations when drilling with a rotary (steerable) assembly.
The magnitude depends on the expected variations. For standard rotary drilling assemblies values between 0.10 and 0.20 are suggested. For rotary steerable assemblies, the magnitude is usually very small, values between 0.01 and 0.10 are suggested.
Consider the following directional wellplan entered in Torque & Drag (the comments describe the different sections of the plan:
Assuming the plan is drilled:
1.With a rotary assembly to kick off point at 500m.
2.Drilling the build up to 1200m with a steerable motor assembly.
3.Drilling tangent to 1500m with a rotary assembly.
4.Drilling a correction run (hole direction) to 1700m with a steerable motor assembly.
5.Drilling tangent to 3000m with a rotary assembly.
Applying the random tortuosities as defined in the table above, this would result in the following chart below. The variation in the blue line, which are actually two lines (the input inclination and the simulated inclination), is barely visible. This is due to the magnitude of the tortuosity being too small for the scale shown.
However, the variation in dogleg severity is very visible. The red line is the simulated dogleg severity (which varies strongly due to the applied tortuosity), whilst the the gray line below is the dogleg severity of the input survey data.
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